1. Field of the Invention
This invention relates generally to methods and compositions for treating wells, and, more specifically to methods and compositions for stimulating multiple intervals in wells. In particular, this invention relates to methods and compositions for diverting well treatment fluids into multiple intervals by alternately displacing diverting agent from the annulus into a subterranean formation and displacing treatment fluid from a tubing string into the subterranean formation.
2. Description of Related Art
Well treatments, such as acid and fracture treatments of subterranean formations are routinely used to improve or stimulate the recovery of hydrocarbons. In many cases, a subterranean formation may include two or more intervals having varying permeability and/or injectivity. Some intervals may possess relatively low injectivity, or ability to accept injected fluids, due to relatively low permeability, high in-situ stress, and/or formation damage. Such intervals may be completed through preparations in a cased wellbore and/or may be completed open hole. In some cases, such formation intervals may be present in a highly deviated or horizontal section of a wellbore, for example, a lateral open hole section. In any case, when treating multiple intervals having variable injectivity it is often the case that most, if not all, of the introduced well treatment fluid will be displaced into one, or only a few, of the intervals having the highest injectivity.
In an effort to more evenly distribute displaced well treatment fluids into each of the multiple intervals being treated, methods and materials for diverting treatment fluids into intervals of lower permeability and/or injectivity have been developed. However, conventional diversion techniques may be costly and/or may achieve only limited success. In this regard, mechanical diversion techniques are typically complicated and costly. Furthermore, mechanical diversion methods are typically limited to cased hole environments and depend upon adequate cement and tool isolation for achieving diversion.
Alternatively, diversion agents such as polymers, suspended solid materials and/or foam have been employed when simultaneously treating multiple intervals of variable injectivity. Such diversion agents are typically pumped into a subterranean formation prior to a well treatment fluid in order to seal off intervals of higher permeability and divert the well treatment fluid to intervals of lower permeability. However, the diverting action of such diversion agents is often difficult to predict and monitor, and may not be successful in diverting treatment fluid into all desired intervals. These problems may be further aggravated in open hole completions, especially in highly deviated completions having large areas of a formation open to the wellbore. The presence of natural fractures may also make diversion more difficult.
Compositions and methods are provided for diverting well treatment fluids into multiple intervals of a subterranean formation having varying permeability and/or injectivity. The disclosed methods and compositions are suitable for use in vertical and horizontal wellbores, as well as for treating cased or open-hole completions in production or injection wells. Surprisingly, superior diversion of well treatment fluids into multiple intervals may be performed and monitored by utilizing both the tubing string and tubing/wellbore annulus as dual treating strings in combination with focused tubing placement during introduction of the treatment fluid.
Advantageously, by spotting a volume of diverting agent in the tubing/wellbore annulus across a desired treatment area of subterranean formation, the diversion agent may be squeezed or displaced into the desired treatment area of the subterranean formation prior to introduction of the treatment fluid through the tubing. Utilizing annular displacement of diversion agent into the formation in combination with displacement of well treatment fluid down the tubing allows focused placement of the treatment fluid by placing and repositioning the tubing in the wellbore, while at the same time monitoring the treating pressure to determine effectiveness of diversion. Advantageously, this allows real time modification of treating procedure in order to match the treatment to the response of the formation.
Further advantageously, maintaining a volume of diversion agent in the annulus above and adjacent to the formation being treated allows displacement of additional diversion agent into the formation when needed and almost instantaneously, without requiring displacement of a tubing volume of fluid.
In one embodiment, several intervals in the open hole section may be treated with the preferred acid formulation without communicating or interfering with other intervals. This procedure is designed to take advantage of dual treating strings, tubing placement, existing near wellbore blockage and a diverting agent, such as an oil soluble diverter system, to create a preferred flow path for a treatment such as an acid stimulation treatment. Examples of suitable diverting agents include, but are not to, those agents found in U.S. Pat. No. 2,803,306, which is incorporated herein by reference in its entirety. A static annular column facilitates real time analysis of down hole pressures. Confining the acid stimulation to a short interval tends to allow greater control of fracture dimensions or matrix penetration.
By combining the introduction of diversion agent stages from the annulus with well treatment fluid stages from the tubing, significant improvements in diversion may be obtained. In one embodiment, by starting a treatment with a tubing string positioned at the lowermost interval to be treated and by pulling the tubing string up the hole successively following diversion and treatment of multiple intervals, the probability of stimulating the most promising or desired intervals of a subterranean formation may be increased. Diverting agent suspended in, for example, a weighted brine is pumped down the annulus with acid pumped down the tubing or drill pipe. The end of tubing is first located at or below the identified stimulation candidate closest to the toe of the well. Diverting agent is pumped to plug leak off zones, natural and created fractures, etc. Treatment fluid such as acid is then pumped at a low rate to create a preferred flow path (or path of least resistance) by etching and worm-holing the formation of the target interval at the end of tubing. This preferred flow path is for the following treatment fluid that will typically be pumped at higher rates and pressures, possibly frac pressures if so desired. The rate is then increased and the fracture or matrix stimulation initiated following etching and worm-holing of the formation face. Tubing is then moved uphole to the next identified interval and the process repeated as many times as needed.
In one disclosed embodiment individual intervals of a subterranean formation may be stimulated with a treatment fluid (including, but not limited to, acid, gelled oil and water systems, solvent, surfactant systems, proppant-laden fluid systems, etc.) while greatly minimizing or eliminating communication and/or interference with other intervals. By utilizing the dual treating string combination of the annular space and tubing, and by focusing placement of the tubing in relation to the desired treating intervals, existing wellbore blockage and a neutrally buoyant diverter system may be employed to create a preferred flow path for the treatment fluid. Advantageously, maintaining a static annular column enables real time analysis of down hole pressures. Furthermore, confining a stimulation to a short interval allows greater control of fracture dimensions or matrix penetration, depending on the type of treatment performed. The disclosed method is particularly advantageous in stimulating high-angle or horizontal wellbores, such as the performance of acid stimulations on oil producing reservoirs, although it may be practiced in virtually any well configuration.
In one disclosed embodiment, the most promising stimulation intervals of a subterranean formation may be identified prior to treatment by, for example, any reservoir evaluations methods known in the art. A stimulation model (such as a matrix inflow or fracture propagation model) may be used to assist in determining an optimum fluid system, fluid properties, fluid volume and injection rate/rates to stimulate each interval. Treatment pressure may then be monitored by measuring the static annular column pressure during treatment, and compared to the pressure predicted by the stimulation model. Alternatively, optimal/predicted treatment pressure may be predicted using hand calculations and/or correlations. Advantageously, such a comparison allows modification of the treatment as required to optimize the treatment using for example, an algorithm disclosed herein.
In one respect, disclosed is a method of treating a wellbore penetrating a subterranean formation and having an inner pipe suspended within the wellbore, including the steps of: (A) introducing diverting agent into the pipe and displacing a volume of the diverting agent through the pipe into an annulus existing between the pipe and the wellbore to a point adjacent or above the subterranean formation; (B) introducing a fluid into the annulus and displacing at least a portion of the diverting agent volume present in the annulus into the subterranean formation; and (C) introducing a well treatment fluid into the pipe and displacing the well treatment fluid through the pipe and into the subterranean formation. The method may also include the steps of: (D) monitoring a surface treating pressure of the annulus or the pipe during the introducing of the well treatment fluid; (E) comparing the measured surface treating pressure, or a treating pressure value calculated based on the measured treating surface pressure, with a target surface treating pressure or target treating pressure value; and (F) ceasing introduction of the well treatment fluid into the pipe if the surface treating pressure or treating pressure value is substantially less than the respective target surface treating pressure or target treating pressure value, displacing an additional portion of the diverting agent volume present in the annulus into the subterranean formation, and then reestablishing introduction of the well treatment fluid into the pipe and displacing the well treatment fluid through the pipe and into the subterranean formation; or (G) continuing the introduction of the well treatment fluid into the pipe if the surface treating pressure or treating pressure value is substantially the same as the respective target surface treating pressure or target treating pressure value.
In one embodiment, the surface treating pressure may be annulus pressure or pipe (tubing, coil-tubing, etc.) pressure. A target surface pressure may be used for comparison, and based on a computer stimulation model, hand held calculation, correlation, or any other suitable dynamic wellbore pressure calculation method. A target treating pressure value includes any pressure value based on surface or bottom hole dynamic treating pressure which is proportional, or otherwise based on magnitude of surface or bottom hole treating pressure (e.g., such as a bottom hole treating pressure calculated based on surface tubing or annulus treating pressure). Advantageously then, any pressure parameter measured at the surface or downhole may be compared directly with a counterpart predicted or estimated pressure, or may be manipulated by calculation and compared to a relevant predicted or calculated value. In one exemplary embodiment, a target treating pressure or target treating pressure value may correspond to treatment conditions at which a formation is hydraulically fractured, or alternatively to an optimum matrix acidizing rate in a selected formation interval. It will be understood with benefit of this disclosure that any pressure treating value suitable for monitoring stimulation characteristics may be employed to achieve the benefits of the disclosed method.
The disclosed method may further include the steps of: (H) raising the pipe and measuring the force or weight required to raise the pipe during the introduction of the well treatment fluid if the surface treating pressure or treating pressure value is substantially greater than the respective target treating pressure or target treating pressure value, and comparing the measured force or weight to raise the pipe with a calculated or measured target weight or force required to raise the pipe in the absence of introduction of fluid into the pipe; and (I) ceasing introduction of the well treatment fluid into the pipe if the force or weight required to raise the pipe during the introduction of the well treatment fluid is substantially more than the target weight or force required to raise the pipe, and displacing an additional portion of the diverting agent volume present in the annulus into the subterranean formation, and then reestablishing introduction of the well treatment fluid into the pipe and displacing the well treatment fluid through the pipe and into the subterranean formation; or (J) continuing the introduction of the well treatment fluid into the pipe if the force or weight required to raise the pipe during the introduction of the well treatment fluid is not substantially more than target weight or force required to raise the pipe.
The method may further include repeating step (H), and then: (K) ceasing introduction of the well treatment fluid into the pipe if the force or weight required to raise the pipe during the introduction of the well treatment fluid is substantially more than the target weight or force required to raise the pipe, and (L) raising an end of the pipe above a point of suspected formation break down in the wellbore, and repeating one or more of the steps (A)-(L) as necessary; or continuing the introduction of the well treatment fluid into the pipe if the force or weight required to raise the pipe during the introduction of the well treatment fluid is substantially the same as the target weight or force required to raise the pipe.
Advantageously, in the disclosed method, the weight required to raise the tubing may be employed as a comparison value, or alternatively force or other weight-based variable may be measured and compared to a target value of like units that is based on a calculated or measured value to raise the pipe in the absence of introduction of the well treatment fluid into the pipe.
In another respect, disclosed is a method of treating at least two identified intervals of a subterranean formation penetrated by a highly deviated or horizontal wellbore having an inner pipe suspended within the wellbore, including: positioning an end of the pipe to a point below a first identified interval of the subterranean formation, the first interval being the identified interval located farthest from the surface; introducing diverting agent into the pipe and displacing a volume of the diverting agent through the pipe into an annulus existing between the pipe and the wellbore to a point adjacent or above the first interval of the subterranean formation; introducing a fluid into the annulus and displacing at least a portion of the diverting agent volume present in the annulus into the subterranean formation; introducing a well treatment fluid into the pipe and displacing the well treatment fluid through the pipe and into the first interval of the subterranean formation; repositioning the end of the pipe within the wellbore to a point adjacent or above at least a second identified interval of the subterranean formation, the second interval being located between the first interval and the surface; introducing a fluid into the annulus and displacing at least a portion of the diverting agent volume present in the annulus into the subterranean formation; introducing a well treatment fluid into the pipe and displacing the well treatment fluid through the pipe and into the second interval of the subterranean formation; and introducing a clean-up fluid into the subterranean formation, the clean-up fluid being effective to remove the diverting agent from the subterranean formation. The method may further include performing the following steps during the introduction of the well treatment fluid into the first and second intervals of the subterranean formation: (A) monitoring a surface treating pressure of the annulus or the pipe during the introducing of the well treatment fluid; (B) comparing the measured surface treating pressure, or a treating pressure value calculated based on the measured treating surface pressure, with a target surface treating pressure range or target treating pressure value range; and (C) ceasing introduction of the well treatment fluid into the pipe if the surface treating pressure or treating pressure value is substantially less than the respective target surface treating pressure range or target treating pressure value range, displacing an additional portion of the diverting agent volume present in the annulus into the subterranean formation, and then reestablishing introduction of the well treatment fluid into the pipe and displacing the well treatment fluid through the pipe and into the subterranean formation; or (D) continuing the introduction of the well treatment fluid into the pipe if the surface treating pressure or surface treating pressure value is substantially within the respective target surface treating pressure range or target treating pressure value range.
The method may further include: (E) raising the pipe and measuring the force or weight required to raise the pipe during the introduction of the well treatment fluid if the surface treating pressure or treating pressure value is substantially greater than the respective target surface treating pressure range or target treating pressure value range, and comparing the measured force or weight to raise the pipe with a target weight or target force based on the force required to raise the pipe in the absence of introduction of fluid into the pipe; and (F) ceasing introduction of the well treatment fluid into the pipe if the force or weight required to raise the pipe during the introduction of the well treatment fluid is substantially more than the target weight or target force, and displacing an additional portion of the diverting agent volume present in the annulus into the subterranean formation, and then reestablishing introduction of the well treatment fluid into the pipe and displacing the well treatment fluid through the pipe and into the subterranean formation; or (G) continuing the introduction of the well treatment fluid into the pipe if the force or weight required to raise the pipe during the introduction of the well treatment fluid is not substantially more than the target weight or target force.
The method may further include repeating the step (E), and then: (H) ceasing introduction of the well treatment fluid into the pipe if the force or weight required to raise the pipe during the introduction of the well treatment fluid is substantially more than the target weight or target force; and (I) raising an end of the pipe above a point of suspected formation break down in the wellbore, and repeating one or more of the steps (A)-(I) as necessary; or (J) continuing the introduction of the well treatment fluid into the pipe if the force or weight required to raise the pipe during the introduction of the well treatment fluid not substantially more that the target weight or target force.
In the practice of the disclosed method, ranges of target surface treating pressure or target treating pressure value may be determined based on wellbore, subterranean formation and/or well treatment parameters. With benefit of this disclosure these value ranges may be selected by those of skill in the art to represent values at which optimum treating or stimulation is occurring based on a comparison of the measured and predicted/calculated values. However, in one embodiment, a range of target surface treating pressure or target treating pressure value may be selected to range from about 5% less than to about 5% greater than (alternatively from about 10% less than to about 10% greater than, alternatively from about 15% less than to about 15% greater than, and further alternatively from about 20% less than to about 20% greater than) a calculated target treating pressure or treating pressure value that is estimated, predicted and/or calculated based on wellbore, formation and/or treatment fluid parameters using computer model, hand calculation, correlation, etc.
In the practice of the disclosed method, a target weight or target force required to raise a treating pipe (tubing, coil tubing, etc.) during introduction of a treatment fluid down the tubing may be with benefit of this disclosure by those of skill in the art to be any value indicative of increased frictional pressure in the pipe/casing annulus due to fluid traveling uphole toward a formation interval other than the desired stimulation interval. However, in one embodiment, a target weight or target force may be equal to about 10% greater than (alternatively about 15% greater than, alternatively about 20% greater than, further alternatively about 25% greater than) a calculated or measured value of weight or force required to raise the pipe in the absence of introduction of the well treatment fluid into the pipe (tubing, coil tubing, etc.). It will be understood with benefit of this disclosure either pressure or weight or force to lift the tubing may be monitored only, while still achieving the benefit of the disclosed method.
In another respect, disclosed is a method of treating a wellbore penetrating a subterranean formation and having an inner pipe suspended within the wellbore, including: (A) introducing diverting agent into the pipe and displacing a volume of the diverting agent through the pipe into an annulus existing between the pipe and the wellbore to a point adjacent or above the subterranean formation; (B) introducing a fluid into the annulus and displacing at least a portion of the diverting agent volume present in the annulus into the subterranean formation; and (C) introducing a well treatment fluid into the pipe and displacing the well treatment fluid through the pipe and into the subterranean formation; (D) monitoring a surface treating pressure of the annulus or the pipe during the introducing of the well treatment fluid and comparing the measured surface treating pressure, or a treating pressure value calculated based on the measured treating surface pressure, with a target surface treating pressure or target treating pressure value; and/or monitoring the force or weight required to raise the pipe during the introduction of the well treatment fluid and comparing the measured force or weight to raise the pipe with a calculated or measured target weight or force required to raise the pipe in the absence of introduction of fluid into the pipe; and modifying one or more of steps (A)-(C) based on at least one of the comparisons.